Commitments, Guarantees and Contingencies	6 Months Ended
Jun. 30, 2020
Commitments and Contingencies Disclosure [Abstract]
Commitments, Guarantees and Contingencies [Text Block]	COMMITMENTS, GUARANTEES AND CONTINGENCIES Power Purchase and Sale Agreements. Our long-term PPAs have been evaluated under the accounting guidance for variable interest entities. We have determined that either we have no variable interest in the PPAs or, where we do have variable interests, we are not the primary beneficiary; therefore, consolidation is not required. These conclusions are based on the fact that we do not have both control over activities that are most significant to the entity and an obligation to absorb losses or receive benefits from the entity’s performance. Our financial exposure relating to these PPAs is limited to our capacity and energy payments. Our PPAs are summarized in Note 9. Commitments, Guarantees and Contingencies to the Consolidated Financial Statements in our 2019 Form 10-K, with additional disclosure provided in the following paragraphs. Square Butte PPA. As of June 30, 2020, Square Butte had total debt outstanding of $272.9 million. Fuel expenses are recoverable through Minnesota Power’s fuel adjustment clause and include the cost of coal purchased from BNI Energy under a long-term contract. Minnesota Power’s cost of power purchased from Square Butte during the six months ended June 30, 2020, was $40.8 million ($41.1 million for the same period in 2019). This reflects Minnesota Power’s pro rata share of total Square Butte costs based on the 50 percent output entitlement. Included in this amount was Minnesota Power’s pro rata share of interest expense of $3.7 million ($4.2 million for the same period in 2019). Minnesota Power’s payments to Square Butte are approved as a purchased power expense for ratemaking purposes by both the MPUC and the FERC. Minnkota Power PSA. Minnesota Power has a PSA with Minnkota Power, which commenced in 2014. Under the PSA, Minnesota Power is selling a portion of its entitlement from Square Butte to Minnkota Power, resulting in Minnkota Power’s net entitlement increasing and Minnesota Power’s net entitlement decreasing until Minnesota Power’s share is eliminated at the end of 2025. Of Minnesota Power’s 50 percent output entitlement, it sold to Minnkota Power approximately 28 percent in 2020 and in 2019. Minnesota Power Short-term PSAs. Minnesota Power has entered into various short-term PSAs to sell 300 MW of energy in 2020 and 2021. These PSAs were entered into to proactively mitigate the uncertainty of customers’ energy needs and potential load loss due to the COVID-19 pandemic. Additional transactions, purchases or sales, could be entered into as the extent and duration of the COVID-19 pandemic becomes known. Coal, Rail and Shipping Contracts. Minnesota Power has coal supply agreements providing for the purchase of a significant portion of its coal requirements through December 2021. Minnesota Power also has coal transportation agreements in place for the delivery of a significant portion of its coal requirements through December 2021. The costs of fuel and related transportation costs for Minnesota Power’s generation are recoverable from Minnesota Power’s retail and municipal utility customers through the fuel adjustment clause. Transmission. We continue to make investments in transmission opportunities that strengthen or enhance the transmission grid or take advantage of our geographical location between sources of renewable energy and end users. These include the GNTL, investments to enhance our own transmission facilities, investments in other transmission assets (individually or in combination with others) and our investment in ATC. Great Northern Transmission Line. As a condition of the 250-MW long-term PPA entered into with Manitoba Hydro, construction of additional transmission capacity was required. As a result, Minnesota Power constructed the GNTL, an approximately 220-mile 500-kV transmission line between Manitoba and Minnesota’s Iron Range that was proposed by Minnesota Power and Manitoba Hydro in order to strengthen the electric grid, enhance regional reliability and promote a greater exchange of sustainable energy. On June 1, 2020, Minnesota Power placed the GNTL into service with project costs of $307.1 million incurred by Minnesota Power through June 30, 2020. Total project costs, including those costs contributed by a subsidiary of Manitoba Hydro, incurred through June 30, 2020 totaled $657.0 million. Also on June 1, 2020, Manitoba Hydro placed the MMTP into service. Environmental Matters. Our businesses are subject to regulation of environmental matters by various federal, state and local authorities. A number of regulatory changes to the Clean Air Act, the Clean Water Act and various waste management requirements have been promulgated by both the EPA and state authorities over the past several years. Minnesota Power’s facilities are subject to additional requirements under many of these regulations. Minnesota Power is reshaping its generation portfolio, over time, to reduce its reliance on coal, has installed cost-effective emission control technology, and advocates for sound science and policy during rulemaking implementation. We consider our businesses to be in substantial compliance with currently applicable environmental regulations and believe all necessary permits have been obtained. We anticipate that with many state and federal environmental regulations and requirements finalized, or to be finalized in the near future, potential expenditures for future environmental matters may be material and require significant capital investments. Minnesota Power has evaluated various environmental compliance scenarios using possible outcomes of environmental regulations to project power supply trends and impacts on customers. We review environmental matters on a quarterly basis. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated based on current law and existing technologies. Accruals are adjusted as assessment and remediation efforts progress, or as additional technical or legal information becomes available. Accruals for environmental liabilities are included in the Consolidated Balance Sheet at undiscounted amounts and exclude claims for recoveries from insurance or other third parties. Costs related to environmental contamination treatment and cleanup are expensed unless recoverable in rates from customers. Air. The electric utility industry is regulated both at the federal and state level to address air emissions. Minnesota Power’s thermal generating facilities mainly burn low-sulfur western sub-bituminous coal. All of Minnesota Power’s coal-fired generating facilities are equipped with pollution control equipment such as scrubbers, baghouses and low NO_X technologies. Under currently applicable environmental regulations, these facilities are substantially compliant with emission requirements. Cross-State Air Pollution Rule (CSAPR). The CSAPR requires certain states in the eastern half of the U.S., including Minnesota, to reduce power plant emissions that contribute to ozone or fine particulate pollution in other states. The CSAPR does not require installation of controls but does require facilities have sufficient allowances to cover their emissions on an annual basis. These allowances are allocated to facilities from each state’s annual budget, and can be bought and sold. Based on our review of the NO_x and SO₂ allowances issued and pending issuance, we currently expect generation levels and emission rates will result in continued compliance with the CSAPR. The ongoing CSAPR “good neighbor” provision and interstate transport litigation is also not currently projected to affect Minnesota Power’s CSAPR compliance. The State of Minnesota has not been identified by the downwind litigant states as a culpable upwind source, and previous EPA air quality modeling has demonstrated that Minnesota is not a significant contributor to downwind air quality attainment challenges. Minnesota Power also does not currently anticipate being affected by the EPA’s expected upcoming rulemakings to address the remand of certain CSAPR rules. Minnesota Power will continue to monitor ongoing CSAPR litigation and associated rulemakings. National Ambient Air Quality Standards (NAAQS). The EPA is required to review the NAAQS every five years. If the EPA determines that a state’s air quality is not in compliance with the NAAQS, the state is required to adopt plans describing how it will reduce emissions to attain the NAAQS. Minnesota Power actively monitors NAAQS developments and compliance costs for existing standards or proposed NAAQS revisions are not expected to be material. NOTE 6. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued) Environmental Matters (Continued) Climate Change. The scientific community generally accepts that emissions of GHG are linked to global climate change which creates physical and financial risks. Physical risks could include, but are not limited to: increased or decreased precipitation and water levels in lakes and rivers; increases or other changes in temperatures; and changes in the intensity and frequency of extreme weather events. These all have the potential to affect the Company’s business and operations. We are addressing climate change by taking the following steps that also ensure reliable and environmentally compliant generation resources to meet our customers’ requirements: •Expanding renewable power supply for both our operations and the operations of others; •Providing energy conservation initiatives for our customers and engaging in other demand side management efforts; •Improving efficiency of our generating facilities; •Supporting research of technologies to reduce carbon emissions from generating facilities and carbon sequestration efforts; •Evaluating and developing less carbon intensive future generating assets such as efficient and flexible natural gas-fired generating facilities; •Managing vegetation on right-of-way corridors to reduce potential wildfire or storm damage risks; and •Practicing sound forestry management in our service territories to create landscapes more resilient to disruption from climate-related changes, including planting and managing long-lived conifer species. EPA Regulation of GHG Emissions. On June 19, 2019, the EPA finalized several separate rulemakings regarding regulating carbon emissions from electric utility generating units. The EPA repealed the Clean Power Plan (CPP), following a determination by the EPA that the CPP exceeded the EPA’s statutory authority under the Clean Air Act (CAA). The primary reason for the repeal was the CPP’s attempt to regulate electric generating unit’s carbon emissions through measures outside of the affected unit’s direct control. The CPP was first announced as a proposed rule under Section 111(d) of the Clean Air Act for existing power plants entitled “Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Generating Units”. With the repeal of the CPP, the Affordable Clean Energy Rule was finalized. The rule establishes emissions guidelines for states to use when developing plans to limit carbon dioxide at coal-fired power plants. The rule identifies heat rate improvements made at individual units as the best system of emission reduction. Affected facilities for Minnesota Power include Boswell Units 3 and 4. Based on our initial review of the rule, many of the candidate heat rate improvements are already installed on Boswell Units 3 and 4. Additionally, the EPA finalized new regulations for the state implementation of the Affordable Clean Energy Rule and any future emission guidelines issued under CAA Section 111(d). States will have three years to submit State Implementation Plans (SIPs), and the EPA has 12 months to review and approve those plans. Since the Affordable Clean Energy Rule allows states considerable flexibility in how to best implement its requirements, Minnesota Power plans to work closely with the MPCA and the Minnesota Department of Commerce, who are currently co-reviewing the rule as the state develops its SIP. If a state does not submit a SIP or submits a SIP that is unacceptable to the EPA, the EPA will develop a Federal Implementation Plan. The MPCA currently plans to develop a SIP for the Affordable Clean Energy Rule and Minnesota Power is working with the MPCA to provide requested information for the SIP. Minnesota had already initiated several measures consistent with those called for under the now repealed CPP and finalized Affordable Clean Energy Rule. Minnesota Power continues implementing its EnergyForward strategic plan that provides for significant emission reductions and diversifying its electricity generation mix to include more renewable and natural gas energy. We are unable to predict the GHG emission compliance costs we might incur as a result of the Affordable Clean Energy Rule and the resulting SIP; however, the costs could be material. Minnesota Power would seek recovery of additional costs through a rate proceeding. NOTE 6. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued) Environmental Matters (Continued) Water. The Clean Water Act requires NPDES permits be obtained from the EPA (or, when delegated, from individual state pollution control agencies) for any wastewater discharged into navigable waters. We have obtained all necessary NPDES permits, including NPDES storm water permits for applicable facilities, to conduct our operations. Steam Electric Power Generating Effluent Limitations Guidelines. In 2015, the EPA issued revised federal effluent limitation guidelines (ELG) for steam electric power generating stations under the Clean Water Act. It set effluent limits and prescribed BACT for several wastewater streams, including flue gas desulphurization (FGD) water, bottom ash transport water and coal combustion landfill leachate. In 2017, the EPA announced a two-year postponement of the ELG compliance date of November 1, 2018, to November 1, 2020, while the agency reconsiders the bottom ash transport water and FGD wastewater provisions. On April 12, 2019, the U.S. Court of Appeals for the Fifth Circuit vacated and remanded back to the EPA portions of the ELG that allowed for continued discharge of legacy wastewater and leachate. On November 22, 2019, the EPA published a draft rulemaking that proposes to allow re-use of bottom ash transport water in FGD scrubber systems with minor discharges related to maintaining system water balance. The proposed rulemaking would also allow future discharge of FGD wastewater discharge provided it meets new BACT standards. A final rulemaking is anticipated in late 2020. The ELG's potential impact on Minnesota Power operations is primarily at Boswell. Boswell currently discharges bottom ash contact water through its NPDES permit, and also has a closed-loop FGD system that does not discharge to surface waters, but may do so in the future if additional water treatment measures are implemented. Under the current ELG rule, bottom ash transport water discharge to surface waters must cease no later than December 31, 2023. Bottom ash contact water will either need to be re-used in a closed-loop process, routed to a FGD scrubber, or the bottom ash handling system will need to be converted to a dry process. The ELG rule provision regarding these two waste-streams are being reconsidered and may change prior to November 1, 2020. Efforts have been underway at Boswell to reduce the amount of water discharged and evaluate potential re-use options in its plant processes. The EPA’s additional reconsideration of legacy wastewater discharge requirements have the potential to reduce timelines for dewatering Boswell’s existing bottom ash pond. The timing of a draft rule addressing legacy wastewater and leachate is currently unknown. At this time, we estimate that the planned dry conversion of bottom ash handling and storage at Boswell in response to the CCR revisions requiring closure of clay-lined impoundments as well as other water re-use practices, will reduce or eliminate the need for additional significant compliance costs for ELG bottom ash water requirements. Compliance costs we might incur related to other ELG waste streams (e.g. legacy leachate) or other potential future water discharge regulations cannot be estimated; however, the costs could be material, including costs associated with wastewater treatment and re-use. Minnesota Power would seek recovery of additional costs through a rate proceeding. Solid and Hazardous Waste. The Resource Conservation and Recovery Act of 1976 regulates the management and disposal of solid and hazardous wastes. We are required to notify the EPA of hazardous waste activity and, consequently, routinely submit reports to the EPA. Coal Ash Management Facilities. Minnesota Power stores or disposes coal ash at four of its electric generating facilities by the following methods: storing ash in clay-lined onsite impoundments (ash ponds), disposing of dry ash in a lined dry ash landfill, applying ash to land as an approved beneficial use and trucking ash to state permitted landfills. Coal Combustion Residuals from Electric Utilities (CCR). In 2015, the EPA published the final rule regulating CCR as nonhazardous waste under Subtitle D of the Resource Conservation and Recovery Act (RCRA) in the Federal Register. The rule includes additional requirements for new landfill and impoundment construction as well as closure activities related to certain existing impoundments. Costs of compliance for Boswell and Laskin are expected to occur primarily over the next 15 years and be between approximately $65 million and $120 million. Compliance costs for CCR at Taconite Harbor are not expected to be material. Minnesota Power would seek recovery of additional costs through a rate proceeding. NOTE 6. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued) Environmental Matters (Continued) Minnesota Power continues to work on minimizing costs through evaluation of beneficial re-use and recycling of CCR and CCR-related waters. In 2017, the EPA announced its intention to formally reconsider the CCR rule under Subtitle D of the RCRA and in March 2018, published the first phase of the proposed rule revisions in the Federal Register. In July 2018, the EPA finalized revisions to elements of the CCR rule, including extending certain deadlines by two years, the establishment of alternative groundwater protection standards for certain constituents and the potential for risk-based management options at facilities based on site characteristics. In August 2018, a U.S. District Court for the District of Columbia decision vacated specific provisions of the CCR rule. The court decision changed the status of three existing impoundments at Boswell that must now be considered unlined. The EPA proposed additional rule revisions in August and December 2019 to address outstanding issues from litigation and closure timelines for unlined impoundments, respectively. These rules are anticipated to be finalized in 2020 and could impact the timing of closure activities for Boswell’s three impoundments. Additionally, the EPA recently released a proposed Part B rulemaking that addresses options for beneficial reuse of CCR materials, alternative liner demonstrations, and other CCR regulatory revisions. Expected compliance costs at Boswell due to the court decision and subsequent rule revisions are reflected in our estimate of compliance costs for the CCR rule noted previously. Minnesota Power would seek recovery of additional costs through a rate proceeding. Other Environmental Matters Manufactured Gas Plant Site. We are reviewing and addressing environmental conditions at a former manufactured gas plant site located in Superior, Wisconsin. SWL&P has been working with the Wisconsin Department of Natural Resources (WDNR) in determining the extent of contamination at the site and surrounding properties. In December 2017, the WDNR authorized SWL&P to transition from site investigation into the remedial design process. As of June 30, 2020, we have recorded a liability of approximately $7 million for remediation costs at this site (approximately $7 million as of December 31, 2019). SWL&P has also recorded an associated regulatory asset as we expect recovery of these remediation costs to be allowed by the PSCW. Remediation costs are expected to be incurred through 2023.

Power Purchase and Sale Agreements. Our long-term PPAs have been evaluated under the accounting guidance for variable interest entities. We have determined that either we have no variable interest in the PPAs or, where we do have variable interests, we are not the primary beneficiary; therefore, consolidation is not required. These conclusions are based on the fact that we do not have both control over activities that are most significant to the entity and an obligation to absorb losses or receive benefits from the entity’s performance. Our financial exposure relating to these PPAs is limited to our capacity and energy payments.

Square Butte PPA. As of June 30, 2020, Square Butte had total debt outstanding of $272.9 million. Fuel expenses are recoverable through Minnesota Power’s fuel adjustment clause and include the cost of coal purchased from BNI Energy under a long-term contract. Minnesota Power’s cost of power purchased from Square Butte during the six months ended June 30, 2020, was $40.8 million ($41.1 million for the same period in 2019). This reflects Minnesota Power’s pro rata share of total Square Butte costs based on the 50 percent output entitlement. Included in this amount was Minnesota Power’s pro rata share of interest expense of $3.7 million ($4.2 million for the same period in 2019). Minnesota Power’s payments to Square Butte are approved as a purchased power expense for ratemaking purposes by both the MPUC and the FERC.

Minnkota Power PSA. Minnesota Power has a PSA with Minnkota Power, which commenced in 2014. Under the PSA, Minnesota Power is selling a portion of its entitlement from Square Butte to Minnkota Power, resulting in Minnkota Power’s net entitlement increasing and Minnesota Power’s net entitlement decreasing until Minnesota Power’s share is eliminated at the end of 2025. Of Minnesota Power’s 50 percent output entitlement, it sold to Minnkota Power approximately 28 percent in 2020 and in 2019.

Minnesota Power Short-term PSAs. Minnesota Power has entered into various short-term PSAs to sell 300 MW of energy in 2020 and 2021. These PSAs were entered into to proactively mitigate the uncertainty of customers’ energy needs and potential load loss due to the COVID-19 pandemic. Additional transactions, purchases or sales, could be entered into as the extent and duration of the COVID-19 pandemic becomes known.

Transmission. We continue to make investments in transmission opportunities that strengthen or enhance the transmission grid or take advantage of our geographical location between sources of renewable energy and end users. These include the GNTL, investments to enhance our own transmission facilities, investments in other transmission assets (individually or in combination with others) and our investment in ATC.

Great Northern Transmission Line. As a condition of the 250-MW long-term PPA entered into with Manitoba Hydro, construction of additional transmission capacity was required. As a result, Minnesota Power constructed the GNTL, an approximately 220-mile 500-kV transmission line between Manitoba and Minnesota’s Iron Range that was proposed by Minnesota Power and Manitoba Hydro in order to strengthen the electric grid, enhance regional reliability and promote a greater exchange of sustainable energy. On June 1, 2020, Minnesota Power placed the GNTL into service with project costs of $307.1 million incurred by Minnesota Power through June 30, 2020. Total project costs, including those costs contributed by a subsidiary of Manitoba Hydro, incurred through June 30, 2020 totaled $657.0 million. Also on June 1, 2020, Manitoba Hydro placed the MMTP into service.

Our businesses are subject to regulation of environmental matters by various federal, state and local authorities. A number of regulatory changes to the Clean Air Act, the Clean Water Act and various waste management requirements have been promulgated by both the EPA and state authorities over the past several years. Minnesota Power’s facilities are subject to additional requirements under many of these regulations. Minnesota Power is reshaping its generation portfolio, over time, to reduce its reliance on coal, has installed cost-effective emission control technology, and advocates for sound science and policy during rulemaking implementation.

We consider our businesses to be in substantial compliance with currently applicable environmental regulations and believe all necessary permits have been obtained. We anticipate that with many state and federal environmental regulations and requirements finalized, or to be finalized in the near future, potential expenditures for future environmental matters may be material and require significant capital investments. Minnesota Power has evaluated various environmental compliance scenarios using possible outcomes of environmental regulations to project power supply trends and impacts on customers.

We review environmental matters on a quarterly basis. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated based on current law and existing technologies. Accruals are adjusted as assessment and remediation efforts progress, or as additional technical or legal information becomes available. Accruals for environmental liabilities are included in the Consolidated Balance Sheet at undiscounted amounts and exclude claims for recoveries from insurance or other third parties. Costs related to environmental contamination treatment and cleanup are expensed unless recoverable in rates from customers.

Air. The electric utility industry is regulated both at the federal and state level to address air emissions. Minnesota Power’s thermal generating facilities mainly burn low-sulfur western sub-bituminous coal. All of Minnesota Power’s coal-fired generating facilities are equipped with pollution control equipment such as scrubbers, baghouses and low NO_X technologies. Under currently applicable environmental regulations, these facilities are substantially compliant with emission requirements.

Cross-State Air Pollution Rule (CSAPR). The CSAPR requires certain states in the eastern half of the U.S., including Minnesota, to reduce power plant emissions that contribute to ozone or fine particulate pollution in other states. The CSAPR does not require installation of controls but does require facilities have sufficient allowances to cover their emissions on an annual basis. These allowances are allocated to facilities from each state’s annual budget, and can be bought and sold. Based on our review of the NO_x and SO₂ allowances issued and pending issuance, we currently expect generation levels and emission rates will result in continued compliance with the CSAPR. The ongoing CSAPR “good neighbor” provision and interstate transport litigation is also not currently projected to affect Minnesota Power’s CSAPR compliance. The State of Minnesota has not been identified by the downwind litigant states as a culpable upwind source, and previous EPA air quality modeling has demonstrated that Minnesota is not a significant contributor to downwind air quality attainment challenges. Minnesota Power also does not currently anticipate being affected by the EPA’s expected upcoming rulemakings to address the remand of certain CSAPR rules. Minnesota Power will continue to monitor ongoing CSAPR litigation and associated rulemakings.

National Ambient Air Quality Standards (NAAQS). The EPA is required to review the NAAQS every five years. If the EPA determines that a state’s air quality is not in compliance with the NAAQS, the state is required to adopt plans describing how it will reduce emissions to attain the NAAQS. Minnesota Power actively monitors NAAQS developments and compliance costs for existing standards or proposed NAAQS revisions are not expected to be material.

Climate Change. The scientific community generally accepts that emissions of GHG are linked to global climate change which creates physical and financial risks. Physical risks could include, but are not limited to: increased or decreased precipitation and water levels in lakes and rivers; increases or other changes in temperatures; and changes in the intensity and frequency of extreme weather events. These all have the potential to affect the Company’s business and operations. We are addressing climate change by taking the following steps that also ensure reliable and environmentally compliant generation resources to meet our customers’ requirements:

The EPA repealed the Clean Power Plan (CPP), following a determination by the EPA that the CPP exceeded the EPA’s statutory authority under the Clean Air Act (CAA). The primary reason for the repeal was the CPP’s attempt to regulate electric generating unit’s carbon emissions through measures outside of the affected unit’s direct control. The CPP was first announced as a proposed rule under Section 111(d) of the Clean Air Act for existing power plants entitled “Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Generating Units”.

With the repeal of the CPP, the Affordable Clean Energy Rule was finalized. The rule establishes emissions guidelines for states to use when developing plans to limit carbon dioxide at coal-fired power plants. The rule identifies heat rate improvements made at individual units as the best system of emission reduction. Affected facilities for Minnesota Power include Boswell Units 3 and 4. Based on our initial review of the rule, many of the candidate heat rate improvements are already installed on Boswell Units 3 and 4.

Additionally, the EPA finalized new regulations for the state implementation of the Affordable Clean Energy Rule and any future emission guidelines issued under CAA Section 111(d). States will have three years to submit State Implementation Plans (SIPs), and the EPA has 12 months to review and approve those plans. Since the Affordable Clean Energy Rule allows states considerable flexibility in how to best implement its requirements, Minnesota Power plans to work closely with the MPCA and the Minnesota Department of Commerce, who are currently co-reviewing the rule as the state develops its SIP. If a state does not submit a SIP or submits a SIP that is unacceptable to the EPA, the EPA will develop a Federal Implementation Plan. The MPCA currently plans to develop a SIP for the Affordable Clean Energy Rule and Minnesota Power is working with the MPCA to provide requested information for the SIP.

Minnesota had already initiated several measures consistent with those called for under the now repealed CPP and finalized Affordable Clean Energy Rule. Minnesota Power continues implementing its EnergyForward strategic plan that provides for significant emission reductions and diversifying its electricity generation mix to include more renewable and natural gas energy. We are unable to predict the GHG emission compliance costs we might incur as a result of the Affordable Clean Energy Rule and the resulting SIP; however, the costs could be material. Minnesota Power would seek recovery of additional costs through a rate proceeding.

Water. The Clean Water Act requires NPDES permits be obtained from the EPA (or, when delegated, from individual state pollution control agencies) for any wastewater discharged into navigable waters. We have obtained all necessary NPDES permits, including NPDES storm water permits for applicable facilities, to conduct our operations.

Steam Electric Power Generating Effluent Limitations Guidelines. In 2015, the EPA issued revised federal effluent limitation guidelines (ELG) for steam electric power generating stations under the Clean Water Act. It set effluent limits and prescribed BACT for several wastewater streams, including flue gas desulphurization (FGD) water, bottom ash transport water and coal combustion landfill leachate. In 2017, the EPA announced a two-year postponement of the ELG compliance date of November 1, 2018, to November 1, 2020, while the agency reconsiders the bottom ash transport water and FGD wastewater provisions. On April 12, 2019, the U.S. Court of Appeals for the Fifth Circuit vacated and remanded back to the EPA portions of the ELG that allowed for continued discharge of legacy wastewater and leachate. On November 22, 2019, the EPA published a draft rulemaking that proposes to allow re-use of bottom ash transport water in FGD scrubber systems with minor discharges related to maintaining system water balance. The proposed rulemaking would also allow future discharge of FGD wastewater discharge provided it meets new BACT standards. A final rulemaking is anticipated in late 2020.

The ELG's potential impact on Minnesota Power operations is primarily at Boswell. Boswell currently discharges bottom ash contact water through its NPDES permit, and also has a closed-loop FGD system that does not discharge to surface waters, but may do so in the future if additional water treatment measures are implemented. Under the current ELG rule, bottom ash transport water discharge to surface waters must cease no later than December 31, 2023. Bottom ash contact water will either need to be re-used in a closed-loop process, routed to a FGD scrubber, or the bottom ash handling system will need to be converted to a dry process. The ELG rule provision regarding these two waste-streams are being reconsidered and may change prior to November 1, 2020. Efforts have been underway at Boswell to reduce the amount of water discharged and evaluate potential re-use options in its plant processes. The EPA’s additional reconsideration of legacy wastewater discharge requirements have the potential to reduce timelines for dewatering Boswell’s existing bottom ash pond. The timing of a draft rule addressing legacy wastewater and leachate is currently unknown.

At this time, we estimate that the planned dry conversion of bottom ash handling and storage at Boswell in response to the CCR revisions requiring closure of clay-lined impoundments as well as other water re-use practices, will reduce or eliminate the need for additional significant compliance costs for ELG bottom ash water requirements. Compliance costs we might incur related to other ELG waste streams (e.g. legacy leachate) or other potential future water discharge regulations cannot be estimated; however, the costs could be material, including costs associated with wastewater treatment and re-use. Minnesota Power would seek recovery of additional costs through a rate proceeding.

Coal Ash Management Facilities. Minnesota Power stores or disposes coal ash at four of its electric generating facilities by the following methods: storing ash in clay-lined onsite impoundments (ash ponds), disposing of dry ash in a lined dry ash landfill, applying ash to land as an approved beneficial use and trucking ash to state permitted landfills.

Coal Combustion Residuals from Electric Utilities (CCR). In 2015, the EPA published the final rule regulating CCR as nonhazardous waste under Subtitle D of the Resource Conservation and Recovery Act (RCRA) in the Federal Register. The rule includes additional requirements for new landfill and impoundment construction as well as closure activities related to certain existing impoundments. Costs of compliance for Boswell and Laskin are expected to occur primarily over the next 15 years and be between approximately $65 million and $120 million. Compliance costs for CCR at Taconite Harbor are not expected to be material. Minnesota Power would seek recovery of additional costs through a rate proceeding.

Minnesota Power continues to work on minimizing costs through evaluation of beneficial re-use and recycling of CCR and CCR-related waters. In 2017, the EPA announced its intention to formally reconsider the CCR rule under Subtitle D of the RCRA and in March 2018, published the first phase of the proposed rule revisions in the Federal Register. In July 2018, the EPA finalized revisions to elements of the CCR rule, including extending certain deadlines by two years, the establishment of alternative groundwater protection standards for certain constituents and the potential for risk-based management options at facilities based on site characteristics. In August 2018, a U.S. District Court for the District of Columbia decision vacated specific provisions of the CCR rule. The court decision changed the status of three existing impoundments at Boswell that must now be considered unlined. The EPA proposed additional rule revisions in August and December 2019 to address outstanding issues from litigation and closure timelines for unlined impoundments, respectively. These rules are anticipated to be finalized in 2020 and could impact the timing of closure activities for Boswell’s three impoundments. Additionally, the EPA recently released a proposed Part B rulemaking that addresses options for beneficial reuse of CCR materials, alternative liner demonstrations, and other CCR regulatory revisions. Expected compliance costs at Boswell due to the court decision and subsequent rule revisions are reflected in our estimate of compliance costs for the CCR rule noted previously. Minnesota Power would seek recovery of additional costs through a rate proceeding.

Manufactured Gas Plant Site. We are reviewing and addressing environmental conditions at a former manufactured gas plant site located in Superior, Wisconsin. SWL&P has been working with the Wisconsin Department of Natural Resources (WDNR) in determining the extent of contamination at the site and surrounding properties. In December 2017, the WDNR authorized SWL&P to transition from site investigation into the remedial design process. As of June 30, 2020, we have recorded a liability of approximately $7 million for remediation costs at this site (approximately $7 million as of December 31, 2019). SWL&P has also recorded an associated regulatory asset as we expect recovery of these remediation costs to be allowed by the PSCW. Remediation costs are expected to be incurred through 2023.